Crude oil flows through thousands of miles of pipelines worldwide. Such pipelines are typically made of mild steel. Due to the nature of the chemical environment to which the pipeline is exposed, i.e., petroleum, brine and dissolved impurities, the pipeline can be susceptible to two forms of corrosive attack as described below.
First, mild steel pipe is susceptible to general corrosion. Corrosion involves two basic chemical processes--oxidation and reduction. With corrosion of mild steel, the oxidative reaction [1] results in the destruction of the metal matrix. EQU Fe.degree..fwdarw.Fe.sup.+2 +2e.sup.- [ 1]
In certain chemical environments, the concurrent reduction reaction results in the formation of atomic hydrogen [2]. EQU H.sup.+ +e.sup.- .fwdarw.H.degree. [2]
In most chemical environments, the atomic hydrogen produced quickly undergoes reaction to form molecular hydrogen [3] which passes harmlessly into the process environment. EQU 2H.degree..fwdarw.H.sub.2(gas) [ 3]
In those cases of typical corrosion, the formation of molecular hydrogen occurs virtually concurrently with the reduction of hydrogen ion to atomic hydrogen. However, there are several chemical environments in which the combination reaction of atomic hydrogen to form molecular hydrogen is impeded, resulting in a higher concentration, or lifetime, of individual hydrogen atoms at or near the vicinity of the steel surface. One such environment, common to the oil industry, is where hydrogen sulfide gas is present in process fluids. Having atomic hydrogen in close proximity to the surface of mild steel pipe can result in a second form of corrosive attack known as hydrogen induced cracking (HIC).
Atomic hydrogen is very soluble in materials such as the mild steel used to fabricate pipe and process vessels due to the very small size of the hydrogen atom. Atomic hydrogen will therefore quickly diffuse, permeate or migrate into solid steel structures. Hydrogen atoms which permeate completely through a steel structure typically combine to form molecular hydrogen which disperses into the external environment. This phenomena does not deleteriously affect the steel. In contrast, HIC susceptible steel contains voids or inclusions into which atomic hydrogen also diffuses. Once inside an inclusion, atomic hydrogen atoms can combine to form molecular hydrogen which cannot diffuse further into the steel matrix. This molecular hydrogen is trapped in the steel, causing the internal pressure in the void to increase as the number of trapped hydrogen molecules increase. At some point, the pressure in the void reaches a level that is high enough to cause propagation of one or more cracks. Such cracking can eventually lead to a total failure of the pipe.
To counteract the potential damage of HIC, various control methodologies are used in the industry. Certain steel alloys and steel manufacturing processes have been developed which are immune to HIC. However, these HIC-resistant alloys are quite expensive and their use can be economically justified in limited situations. A second control methodology is removal from the process stream of the compound or compounds which impede the formation of molecular hydrogen, which in the case of petroleum feeds is hydrogen sulfide gas. Hydrogen sulfide removal, known as "sweetening," is well known in the oil industry and used in many locations, but it is not always a cost effective choice. A third HIC control method is the addition of chemical inhibitors to the process stream at very low concentration levels.
HIC inhibitors are bi-functional in that they work (1) by lowering the general corrosion rate caused by various feedstock components; and (2) by reducing or eliminating the number of free hydrogen atoms that can migrate into the interior of the walls of the steel pipe. There are a large number of commercially available HIC inhibitors, the effectiveness of which vary with the specific chemical composition of the process stream. Selection of an appropriate inhibitor is further complicated by the fact that an inhibitor may be effective at reducing hydrogen permeation, while at the same time have a poor ability to inhibit general corrosion. Thus, each additive must be tested under process conditions to determine its effectiveness as a general corrosion inhibitor and a hydrogen permeation inhibitor.
Various test methods have been developed for independently testing corrosion and HIC inhibitors. A widely used procedure for corrosion inhibitor evaluation utilizes a "wheel oven." A wheel oven consists of a wheel rotating at a fixed RPM for a given time period in a temperature controlled oven. A number of small sealed bottles are attached to the wheel. The bottles contain a fixed concentration of inhibitor in the aqueous environment to be tested, as well as a preweighed test sample. At the end of the test period the test samples are removed, cleaned and weighed. A general corrosion rate is calculated from sample weight loss and sample area. A ranking of inhibitor performance can be prepared. There are a number of limitations associated with such wheel oven measurements. In particular, since the same solution and gases are present in the bottle throughout the test, the test simulates only a static system and the build up of corrosion products can change solution chemistry. Further, only the general corrosion rate can be determined, not pitting rate, nor can mechanistic corrosion processes or surface effects be determined.
In order to address some of the limitations of the wheel oven, more sophisticated electrochemical methods for corrosion rate measurement were developed. A few of these methods are listed below. In one such method, very small spontaneous current spikes associated with metal oxidation are measured. The data is collected and analyzed by software to develop corrosion rate information. While this procedure is noninvasive to the sample, it requires sophisticated software and data collection instrumentation. In another method, which may be referred to as a polarization resistance method, a small anodic and cathodic potential, typically .+-.10 millivolts (mv), is applied to the corroding metal substrate and the resulting current is measured. These values are then used to calculate a general corrosion rate. In a third method, a relatively large cathodic and anodic potential, typically 2-300 mv, is applied to the corroding metal substrate and a current is measured. Through data analysis a general corrosion rate is determined, as well as a semiquantitative calculation of pitting rate. This method is damaging to the inhibitor/metal surface film so that typically only one measurement may be taken per 24 hour period. The corrosion rate may also be determined by electrochemical impedance spectroscopy. In this method, a small amplitude sine wave signal, maximum 5 mv, of varying frequency, typically 10.sup.-5 to 10.sup.5 Hertz, is applied to the corroding metal. Through analysis of the applied potential, resulting current and phase angle, mechanistic information as to the corrosive phenomena occurring may be obtained.
In contrast to corrosion rate testing, which is widely practiced using many different methods, inhibitors are not routinely evaluated as to their effectiveness as atomic hydrogen permeation mitigators. Further, there are a limited number of methods available for monitoring hydrogen permeation. In a first method, the permeation of corrosion generated hydrogen into a steel container of fixed volume is monitored by determining the increase in pressure within the container. In a second method, HIC mitigation is evaluated as a function of hydrogen permeation current density, which is the measured variable. Both of these methods are utilized in conjunction with the present invention.
While a number of methods exist for determining the general corrosion rate, and at least two methods exist for the evaluation of hydrogen permeation inhibition effectiveness, the prior art methods do not allow simultaneous measurement of an inhibitor's ability to inhibit hydrogen permeation and general corrosion. Using the teachings of the prior art, such measurements are carried out in different test cells. The results obtained from the same test cell are known to be reliable to only about .+-.25% due to factors such as variation in stir rate and gas flow rate, temperature fluctuations, the difficulty in pipetting small volumes of very viscous corrosion inhibitors, cell cleanliness, and variation in the brine makeup and in the ratio of solution volume to sample surface area. Thus, where corrosion inhibition and hydrogen permeation inhibition are not tested in the same cell simultaneously, variation in cell conditions hampers reliable evaluation of HIC inhibitor overall performance.
The above discussion of HIC and the use of corrosion inhibitors to control it, pertains to carbon steels having yield strengths less than about 90,000 psi. In the case of higher strength steels having a yield strength above 90,000 psi, the nature of the stress cracking and failure is different. Unlike the more gradual blistering and cracking which ultimately leads to fracture failure in the former class of steels, an instantaneous, catastrophic failure occurs in high strength steels. This is known as sulfide stress cracking (SSC). Due to the instantaneous nature of SSC failures, the use of corrosion inhibition additives to the fluid stream is not considered a viable control method. When SSC problems are anticipated, they are typically addressed metallurgically.
It is therefore an object of this invention to provide a more reliable means for evaluating HIC inhibitor performance.
It is a further object of this invention to provide an improved means for selecting an HIC inhibitor.